1. Field of the Invention
This invention generally relates to a method and an apparatus for detecting and monitoring various conditions (e.g. seismic, pressure, and temperature signals) in and around a borehole. More particularly, the invention relates to a sensor array suitable for long-term placement inside a well, thereby permitting diverse measurements concerning the state of the well, flows inside the well, and the evolution of the reservoir over time.
2. Description of the Related Art
During the production of hydrocarbons from an underground reservoir or formation, it is important to determine the development and behavior of the reservoir and to foresee changes which will affect the reservoir. Various methods for determining and measuring downhole parameters for forecasting the behavior of the reservoir are well known in the art.
One method includes placing one or more sensors downhole adjacent the reservoir and recording seismic signals generated from a source often located at the surface. Hydrophones, geophones, and accelerometers are three typical types of sensors used for recording such seismic signals. Hydrophones respond to pressure changes in a fluid excited by seismic waves, and consequently must be in contact with the fluid to function. Hydrophones are non-directional and respond only to the compressional component of the seismic wave. They can be used to indirectly measure the shear wave component of a seismic wave when the shear component is converted to a compressional wave (e.g. at formation interfaces or at the wellbore-formation interface). Geophones measure both compressional and shear waves directly They include particle velocity detectors and typically provide three-component velocity measurement. Accelerometers also measure both compression and shear waves directly, but instead of detecting particle velocities, accelerometers detect accelerations, and hence have increased sensitivity at higher frequencies. Accelerometers are presently available with three-axis acceleration measurements. Both geophones and accelerometers can be used to determine the direction of arrival of the seismic wave. Any of the above devices or a combination thereof can be used to measure seismic signals within a borehole. Additional sensors that may prove beneficial to reservoir engineers include, but are not limited to, temperature sensors, pressure transducers, and position monitors (gyroscopes). Any or all of these sensors may be deployed concurrently with seismic sensors to help the engineer determine reservoir status.
In the past, wireline tools have been used to deploy well logging or vertical seismic sensors to profile reservoirs from within the bore of a well. Wireline sondes can contain a large assortment of sensors enabling various parameters to be measured, including acoustic noise, natural radioactivity, temperature, pressure, etc. The sensors may be positioned inside the production tubing for carrying out localized measurements of the nearby annulus or for monitoring fluid flowing through the production tubing. Although effective, wireline sondes are not considered a long term solution. Often a more permanent method for equipping wells with sensors is desired. Permanent sensor installations grant the reservoir engineer the ability to record time-lapse measurements over periods spanning days, months, and years. Such time-deferred measurements allow reservoir operators a more detailed picture of the amount of reserves remaining and the rate at which they are diminishing.
Additionally, many sensors, including accelerometers and geophones, must be mechanically coupled to the well formation in order to be effective. While wireline sensors of this type are currently in existence, they are often bulky and require special actuators to couple the sensor to the casing or formation wall and are not considered permanent. Permanent sensor arrays also provide the reservoir engineer with the ability to record measurements over a broader region and for longer periods of time.
Most of the cost of a typical seismic survey lies within the data acquisition methods currently performed upon temporary arrays of surface sources and receivers. Long-term emplacement of the receivers has the potential of significantly lowering data acquisition and deployment costs. There are two major benefits of long-term emplacement of sensors, first, repeatability is improved, and second, by positioning the receivers closer to the reservoir, noise is reduced and vertical resolution of the seismic information is improved. Further, from an operational standpoint, it is preferred that receivers be placed in the field early to provide the capability of repeating 3-D seismic surveys at time intervals more dependent on reservoir management requirements than on data acquisition constraints. By obtaining a sequence of records distributed over a long period of time, it becomes possible to monitor the movement of fluid in the reservoirs, and to thereby obtain information needed to improve the volume of recovered hydrocarbons and the efficiency with which they are recovered. For whatever the reason long-term emplacement is desired, it is of utmost importance that emplaced sensors move as little as possible throughout their lifetime. Movement in long-term sensors can disrupt the credibility of data collected over long periods of time.
A xe2x80x9cpermanentxe2x80x9d method that has been previously used involves the attaching of sensors to the exterior of the well casing as it is installed. Following installation, the annulus around the casing is then cemented such that when the cement sets, the sensors are permanently and mechanically coupled to the casing and formation. One major drawback to a system of this type, is that there is considerable chance for a failure during the installation process, a failure that will, for the most part, not be detectable until after the cementing process is complete. If a system becomes inoperable following cementing, it becomes prohibitively expensive and difficult to repair the system and it is left in place, in an inoperable condition. Another limitation of this system is that it must be installed during the well construction process, before completion. Such a system can not be added to a well at a later date if desired.
An apparatus for a permanent sensor array has been presented in U.S. patent application Ser. No. 09/260,746 Method for Permanent Emplacement of Sensors Inside Casing filed Mar. 1, 1999 by John W. Minear hereby incorporated herein by reference. Minear presents a system whereby an array of permanent sensor devices are installed within well casing by having them mounted about the outer profile of a string of coiled tubing installed therein. In one instance, the sensors of Minear are mounted upon spring loaded carriers that are compressed during installation and held into place following installation by the stored energy of the springs loaded carriers. This arrangement allows for the sensors to be mechanically coupled to the casing, with little chance of positional changes over long periods of time. The main advantage that such a system provides is the ability to have a permanent sensor array that can be retrieved in the event of a system failure. Minear also provides a solution whereby the sensors of the array are connected to one another and the surface by a durable and flexible cable. The cable of Minear is as durable and crush resistant as metal conduit, but flexible to allow effective emplacement of sensors against the casing wall.
The only potential drawback to the system as proposed by Minear is that there may be a significant risk of damage to the sensor pods during array installation. As sensors are engaged through the casing, they are held against the casing wall by the spring loaded carriers and are essentially xe2x80x9cdraggedxe2x80x9d to their final destination. During such an operation, it is possible that one or more of the sensor devices will become damaged and inoperative. Unless expensive fault isolators are installed in conjunction with each sensor, a damaged sensor on a typical array can require the retrieval of the entire system for repairs.
Even after installation is successfully completed, there remains a chance for failures to occur in the many months following the original installation. If the entire sensor array must be removed from the wellbore for repairs, long term data analysis can no longer be performed with precision as the position of each sensor will have changed relative to the formation, making most extended time lapsed xe2x80x9cbeforexe2x80x9d and xe2x80x9cafterxe2x80x9d data comparisons invalid. For this reason, an arrangement and method that ensures the effective operation of a xe2x80x9cpermanentxe2x80x9d sensor array for many years following installation is of utmost importance to reservoir engineers.
A reliable permanent sensor array system has long been identified as highly desirable by reservoir engineers. The system could be compatible with a variety of existing standard surface seismic sources in order to provide high quality seismic measurements. By emplacing the sensors permanently in the well, the variances that result from repositioning the sensors between repeat surveys of a long term monitoring project can be eliminated. The sensor array must be reliable as it may need to be in place for as many as 10 years to provide the necessary surveys and must be capable of surviving hostile environments, including elevated temperatures, pressures, and corrosive wellbore fluids. Finally, the permanent sensor array must be economical to produce and deploy.
Current means of communication with the surface for sensor arrays are either digital or analog. Analog communication typically requires a twisted pair of wires to be run to the surface for each of the deployed sensors. For arrays with large amounts of sensors, this communication can require a very large umbilical cable to be run from the surface to the sensors. For example, an array of 100 sensor pods containing 3 accelerometers (one for each axis) would require a 600 wire umbilical cable. For most installations, this is too large to be feasible. Additionally, the accuracy of deployed sensors in such a system can be reduced as a result of cable attenuation and crosstalk effects. Environmental tolerance is also generally poor due to variation in the cable characteristics after prolonged exposure to elevated temperature and pressure.
Alternatively, a digital communication system can be deployed in place of the analog communication system to offer a dramatic reduction in required cable size. For the example above, a comparable digital array of sensors could be arranged such that all 100 pods and all 300 sensors could communicate to the surface with one wire or a fiber optic line. A major drawback of the digital method described above is that failure of one sensor pod can destroy the entire communication link to all others.
The present invention overcomes these deficiencies of the prior art.
The deficiencies of the prior art can be resolved using a system that is based on a series of data accumulation hubs, connected together by high speed communication backbone for routing data and power signals. Each hub is then connected to an individual array of sensor pods which contain the actual sensor elements and minimal interface electronics. Upper and lower strings of sensor pods are connected to each hub by flexible elastomeric cable to ease the emplacement of the sensors against the casing.